The term “natural gas” is applied to gas produced from underground accumulations of widely varying composition. The main constituent of natural gas is methane. Apart from methane, natural gas generally includes other hydrocarbons, nitrogen, carbon dioxide, sometimes a small proportion of hydrogen sulphide, and often water. Hydrocarbon constituents include ethane (C2), propane (C3), butane (C4), pentane (C5), hexane (C6), heptane (C7), etc. Hydrocarbons having 5 or more carbon atoms are generally referred to as C5+. Constituents of a natural gas stream other than methane will be referred to as contaminants in the specification and in the claims. The invention relates in particular to the removal of contaminants by a combination of adsorption and condensation.
The lighter constituents, C1 up to and including C4, are in gaseous phase at atmospheric temperatures and pressures. The heavier constituents, C5+, are in gaseous phase when at elevated temperatures during production from the subsurface and in liquid phase when the gas mixture has cooled down. Natural gas containing such heavier constituents is known as “wet gas” as distinct from dry gas containing none or only a small proportion of liquid hydrocarbons.
The removal of contaminants, in particular water and hydrocarbons, from natural gas streams is important to prevent problems that can occur during their transportation. In the event that untreated natural gas is transported through pipeline systems the pressure loss, which is inevitable in pipeline systems, causes liquids to be formed as a result of condensation of water and/or hydrocarbons. Slugs of these liquids can cause problems, such as plugging of pipelines and distribution systems. In addition, liquid water can accelerate corrosion.
A useful parameter for indicating the potential liquids content of any gas is in terms of the dewpoint. The dewpoint is generally defined as the temperature to which a gas must be cooled (at constant composition) in order for it to become saturated with respect to water vapour (i.e. attain equilibrium with a liquid). For mixtures such as natural gas, instead of a dewpoint the cricondenbar (highest pressure at which a vapour-liquid equilibrium is present) or cricondentherm (highest temperature at which a vapour-liquid equilibrium is present) are used.
In order to prevent the formation of liquids in a natural gas stream, contaminants, in particular water and, if applicable, hydrocarbons should be removed in order to lower the cricondentherm of the natural gas stream. In the case of natural gas with a low content of hydrocarbons other than methane, or in the case when hydrocarbon liquid formation is allowable, only water removal is required. Generally, however, there is a need for the removal of both water and hydrocarbons, which are more difficult to remove, from the natural gas, especially to achieve a certain desired cricondentherm.
A known process for the removal of water and hydrocarbons from a natural gas stream is for example described in the article “Solving storage problems” by T. Schulz, J. Rajani, D. Brands, Hydrocarbon Engineering June 2001, pages 55-60. In the known process, the natural gas stream is contacted with an adsorbent bed in order to remove the water and hydrocarbon contaminants. After some time on stream the adsorption bed needs to be regenerated, which time also depends on the desired quality of the purified gas stream leaving the adsorbent bed because of preferential adsorption of different types of contaminants.
Adsorption of components from a gas mixture through solid adsorbents is a thermal exothermic process, known as thermal swing adsorption (TSA). This process is generally reverted by applying heat to the adsorbent and adsorbate phase. If the heat applied is sufficient, the adsorbed components will leave the adsorbent internal surface and pores. To complete regeneration, the adsorbent is once again cooled to its initial temperature. This reversion of the adsorption process is called regeneration.
Therefore in total three adsorption beds are provided in the known process, one of them being in adsorption mode, one of them being regenerated by passing a slipstream of the untreated natural gas stream at an elevated temperature over the bed so that adsorbed contaminants are removed from the bed, and one of them being cooled by the slipstream after the bed was regenerated. The slipstream is first passed through the bed to be cooled, then heated, and passed through the bed to be regenerated. The slipstream takes up contaminants that are removed from the adsorbent bed in regeneration mode. The contaminated slipstream is then passed through an air and water cooler, so that contaminants that condense at the temperature of water (above hydrate formation temperature) can be separated off as a liquid in a separator. The flash gas is recycled to the natural gas stream to be treated, upstream of adsorption bed in adsorption mode. Unfortunately, the water cooler and separator are not very efficient. Accordingly, significant levels of C5+ hydrocarbon contaminants can build up in the recycle stream to the adsorption bed, reducing adsorption efficiency. Alternatively, cooling with a refrigerant is also problematic solid hydrates can form in the cooler and knock out pots.
A problem in the use of adsorbent beds to remove water and/or hydrocarbons from a natural gas stream is that it is not always possible to achieve a sufficiently low cricondentherm of the resulting purified gas stream from the bed in adsorption mode. Therefore, there is a need for a process enabling the removal of contaminants, typically both water and hydrocarbons, from the natural gas, to achieve a certain desired cricondentherm.
In accordance with U.S. Pub. No. 2007/0267328, published Nov. 22, 2007, a process is provided for removing contaminants from a natural gas stream. The process comprises the steps of: (a) contacting part of the natural gas stream as a first gas stream at an elevated temperature with a first adsorbent bed in regeneration mode, to remove contaminants present on the first adsorbent bed, and to obtain a second gas stream that is enriched in contaminants compared to the first gas stream; (b) submitting the second gas stream to a gas/liquid separation step comprising cooling the second gas stream to a temperature such that at least some contaminants begin to condense into a first liquid phase that is rich in contaminants, and separating the first liquid phase from the second gas stream to create a third gas stream; wherein the gas/liquid separation step forms a first gas/liquid separation step, and wherein the process further comprises (c) submitting the third gas stream to a second gas/liquid separation step to obtain a second liquid phase that is rich in contaminants, and a lean gas stream.
In a particularly advantageous embodiment of the process according to U.S. Pub. No. 2007/0267328, the second gas/liquid separation in step (c) is effected by means of an accelerated velocity inertia separator. Such a separator creates a fluid stream flowing at accelerated velocity and causes said fluid stream to cool to a temperature at which water and hydrocarbons will condense into a second liquid water/hydrocarbon phase. The accelerated velocity inertia separator is advantageously a supersonic inertia separator and the fluid stream flows at supersonic velocity. Further, a swirling motion can suitably be induced to the fluid stream flowing at supersonic velocity, thereby causing the contaminants, in particular water and hydrocarbons, to flow to a radially outer section of a collecting zone in the stream. However, after leaving the accelerated velocity inertia separator, the gas stream must be compressed to adsorption pressure. The compression step reduces the energy efficiency of the process.